Petroleum companies frequently use seismic surveys in their search for exploitable petroleum reservoirs. A seismic survey is an attempt to map the subsurface of the earth by sending sound energy down into the ground and recording the “echoes” that return from the rock layers below. The source of the down-going sound energy might come from explosions or seismic vibrators on land, and air guns in marine environments. During a seismic survey, the energy source is moved across the surface of the earth above the geologic structure of interest. Each time the source is triggered, it generates a seismic signal that travels downward through the earth and is partially reflected from boundaries between different rock types. These reflections cause sound energy waves to return toward the surface where they are detected by a set of spaced geophones or seismic energy detectors. The detectors generate electrical signals representative of the sound energy arriving at their locations.
The acoustic energy detected by the seismic detectors is generally amplified and then recorded or stored in either analog or digital form on some record medium. The recording is made as a function of time after the triggering of the source. The recorded data may be transported to a computer and displayed in the form of traces, i.e., plots of the amplitude of the reflected seismic energy as a function of time for each of the geophones or seismic energy detectors. Such displays or data may be processed to simplify the interpretation of the arriving acoustic energy at each seismic detector in terms of the subsurface layering of the earth's structure. Data from multiple explosion/recording location combinations may be combined to create a nearly continuous profile of the subsurface that may extend for many miles.
Survey types are often distinguished in terms of the pattern of recording locations on the earth's surface. As viewed from above, the recording locations may be laid out in a straight line, in which case the result is a two-dimensional (2-D) seismic survey. A 2-D survey can be thought of as a cross-sectional view (a vertical slice) of the earth formations lying underneath the line of recording locations. Alternatively, the recording locations may be laid out in a two-dimensional array pattern on the surface, in which case the result is a three-dimensional (3-D) seismic survey. A 3-D survey produces a data “cube” or volume that is, at least conceptually, a 3-D picture of the subsurface that lies beneath the survey area.
A seismic survey is composed of a very large number of individual seismic recordings or traces. In a typical 2-D survey, there will usually be several tens of thousands of traces, whereas in a 3-D survey the number of individual traces may run into the multiple millions of traces. In the past, the traces were recorded in analog form, but modem seismic traces are generally recorded in digital form. The digital samples are usually acquired at 0.004 second (4 millisecond or “ms”) intervals, although 2 millisecond and 1 millisecond sampling intervals are also common. Thus, each digital sample in a seismic trace is associated with a travel time (in the case of reflected energy a two-way travel time from the surface to the reflector and back to the surface again). Further, the surface position of every trace in a seismic survey is carefully recorded and is generally made a part of the trace itself (as part of the trace header information). This allows the seismic information contained within the traces to be later correlated with specific subsurface locations, thereby providing a means for posting and contouring seismic data, and attributes extracted therefrom, on a map (i.e., “mapping”). General information pertaining to 3-D data acquisition and processing may be found in Chapter 6, pages 384-427, of Seismic Data Processing by Ozdogan Yilmaz, Society of Exploration Geophysicists, 1987, the disclosure of which is incorporated herein by reference.
The data volume in a 3-D survey is amenable to viewing in a number of different ways. First, horizontal “constant time slices” may be extracted from the seismic volume by collecting all digital samples that occur at the same travel time. This operation results in a 2-D plane of seismic data. By animating a series of 2-D planes it is possible for the interpreter to pan through the volume, giving the impression that successive layers are being stripped away so that the information that lies underneath may be observed. Similarly, a vertical plane of seismic data may be taken at an arbitrary azimuth through the volume by collecting and displaying the seismic traces that lie along a particular line. This operation, in effect, extracts an individual 2-D seismic line from within the 3-D data volume.
Seismic data that have been properly acquired and processed can provide a wealth of information to the explorationist, one of the individuals within an oil company whose job it is to locate potential drilling sites. For example, a seismic profile gives the explorationist a broad view of the subsurface structure of the rock layers and often reveals important features associated with the entrapment and storage of hydrocarbons such as faults, folds, anticlines, nonconformities, and sub-surface salt domes and reefs, among many others. During the computer processing of seismic data, estimates of subsurface velocity are routinely generated and near surface inhomogeneities are detected and displayed. In some cases, seismic data can be used to directly estimate rock porosity, water saturation, and hydrocarbon content. Less obviously, seismic waveform attributes such as phase, peak amplitude, peak-to-trough ratio, and a host of others, can often be empirically correlated with known hydrocarbon occurrences. This correlation can be applied to seismic data collected over new exploration targets. In brief, seismic data provides some of the best subsurface structural and stratigraphic information that is available, short of drilling a well.
That being said, one of the most challenging tasks facing the seismic interpreter—one of the individuals within an oil company that is responsible for reviewing and analyzing the collected seismic data—is locating these stratigraphic and structural features of interest within a potentially enormous seismic volume. By way of example only, it is often important to know the location of discontinuities in a seismic survey.
Discontinuities are sudden changes in the seismic data, and may be indicative of faults and other interesting interruptions in formation geometry. Discontinuity and continuity may be considered opposite ends of a continuity spectrum, so that a high continuity measurement is indicative of a low discontinuity, and conversely, a high discontinuity measurement is indicative of a low continuity.
Faults are particularly significant geological features in petroleum exploration for a number of reasons including the following: 1) they are often associated with the formation of subsurface traps in which petroleum might accumulate, and 2) they can affect (either positively or negatively) production of nearby wells. Given the enormous amount of data collected in a 3-D volume, automated methods of enhancing the appearance of such subsurface features are sorely needed.
Others have suggested methods for enhancing the appearance of discontinuities in seismic data. See, for example, Bahorich et al., U.S. Pat. No. 5,563,949, Gersztenkorn, U.S. Pat. No. 5,892,732, and Marfurt et al., U.S. Pat. No. 5,940,778. Such methods have given inadequate results or have proven suitable only for use on zero-mean data. A more versatile discontinuity measurement method that provides high-quality results would prove commercially advantageous.